1. Field of the Invention
The invention relates generally to the field of well logging. More particularly, the invention relates to improved techniques in which instruments equipped with antenna systems having transverse or tilted magnetic dipoles are used for improved electromagnetic measurements of subsurface formations.
2. Background Art
Various well logging techniques are known in the field of hydrocarbon exploration and production. These techniques typically use instruments or tools equipped with sources adapted to emit energy into a subsurface formation that has been penetrated by a borehole. In this description, “instrument” and “tool” will be used interchangeably to indicate, for example, an electromagnetic instrument (or tool), a wire-line tool (or instrument), or a logging-while-drilling tool (or instrument). The emitted energy interacts with the surrounding formation to produce signals that are then detected and measured by one or more sensors. By processing the detected signal data, a profile of the formation properties is obtained.
Electromagnetic (EM) induction and propagation logging are well-known techniques. The logging instruments are disposed within a borehole to measure the electrical conductivity (or its inverse, resistivity) of earth formations surrounding the borehole. In the present description, any reference to conductivity is intended to encompass its inverse, resistivity, or vice versa. A typical electromagnetic resistivity tool comprises a transmitter antenna and one or more (typically a pair) receiver antennas disposed at a distance from the transmitter antenna along the axis of the tool (see FIG. 1).
Induction tools measure the resistivity (or conductivity) of the formation by measuring the current induced in the receiver antenna as a result of magnetic flux induced by currents flowing through the emitting (or transmitter) antenna. An EM propagation tool operates in a similar fashion but typically at higher frequencies than do induction tools for comparable antenna spacings (about 106 Hz for propagation tools as compared with about 104 Hz for the induction tools). A typical propagation tool may operate at a frequency range of 1 kHz-2 MHz.
Conventional transmitters and receivers are antennas formed from coils comprised of one or more turns of insulated conductor wire wound around a support. These antennas are typically operable as sources and/or receivers. Those skilled in the art will appreciate that the same antenna may be use as a transmitter at one time and as a receiver at another. It will also be appreciated that the transmitter-receiver configurations disclosed herein are interchangeable due to the principle of reciprocity, i.e., the “transmitter” may be used as a “receiver”, and vice-versa.
A coil carrying a current (e.g., a transmitter coil) generates a magnetic field. The electromagnetic energy from the transmitter antenna is transmitted into the surrounding formation, which induces a current (eddy current) flowing in the formation around the transmitter (see FIG. 2A). The eddy current in the formation in turn generates a magnetic field that induces an electrical voltage in the receiver antennas. If a pair of spaced-apart receivers are used, the induced voltages in the two receiver antennas would have different phases and amplitudes due to geometric spreading and absorption by the surrounding formation. The phase difference (phase shift, Φ) and amplitude ratio (attenuation, A) from the two receivers can be used to derive resistivity of the formation. The detected phase shift (Φ) and attenuation (A) depend on not only the spacing between the two receivers and the distances between the transmitter and the receivers, but also the frequency of EM waves generated by the transmitter.
In conventional induction and propagation logging instruments, the transmitter and receiver antennas are mounted with their axes along the longitudinal axis of the instrument. Thus, these tools are implemented with antennas having longitudinal magnetic dipoles (LMD). An emerging technique in the field of well logging is the use of instruments including antennas having tilted or transverse coils, i.e., where the coil's axis is not parallel to the longitudinal axis of the support or borehole. These instruments are thus implemented with a transverse or tilted magnetic dipole (TMD) antenna. Those skilled in the art will appreciate that various ways are available to tilt or skew an antenna. Logging instruments equipped with TMD antennas are described in U.S. Pat. Nos. 6,163,155, 6,147,496, 5,115,198, 4,319,191, 5,508,616, 5,757,191, 5,781,436, 6,044,325, and 6,147,496.
FIG. 2A presents a simple picture, which is applicable if the borehole penetrates the formation in a direction perpendicular to the sedimentation layers. However, this is often not the situation. Often the borehole penetrates the formation layers at an angle other than 90 degrees (FIG. 2B). When this happens, the formation plane is said to have a relative dip. A relative dip angle, θ, is defined as the angle between the borehole axis (tool axis) and the normal to the plane of the formation (not shown).
Drilling techniques known in the art include drilling wellbores from a selected geographic position at the earth's surface, along a selected trajectory. The trajectory may extend to other selected geographic positions at particular depths within the wellbore. These techniques are known collectively as “directional drilling” techniques. One application of directional drilling is the drilling of highly deviated (with respect to vertical), or even horizontal, wellbores within and along relatively thin hydrocarbon-bearing earth formations (called “pay zones”) over extended distances. These highly deviated wellbores are intended to greatly increase the hydrocarbon drainage from the pay zone as compared to “conventional” wellbores which “vertically” (substantially perpendicularly to the layering of the formation) penetrate the pay zone.
In highly deviated or horizontal wellbore drilling within a pay zone, it is important to maintain the trajectory of the wellbore so that it remains within a particular position in the pay zone. Directional drilling systems are well known in the art which use “mud motors” and “bent subs” as means for controlling the trajectory of a wellbore with respect to geographic references, such as magnetic north and earth's gravity (vertical). Layering of the formations, however, may be such that the pay zone does not lie along a predictable trajectory at geographic positions distant from the surface location of the wellbore. Typically the wellbore operator uses information (such as LWD logs) obtained during wellbore drilling to maintain the trajectory of the wellbore within the pay zone, and to further verify that the wellbore is, in fact, being drilled within the pay zone.
Techniques known in the art for maintaining trajectory are described for example in ribe et al., Precise Well Placement using Rotary Steerable Systems and LWD Measurement, SOCIETY OF PETROLEUM ENGINEERS, Paper 71396, Sep. 30, 2001. The technique described in this reference is based upon LWD conductivity sensor responses. If, as an example, the conductivity of the pay zone is known prior to penetration by the wellbore, and if the conductivities of overlying and underlying zones provide a significant contrast with respect to the pay zone, a measure of formation conductivity made while drilling can be used as a criterion for “steering” the wellbore to remain within the pay zone. More specifically, if the measured conductivity deviates significantly from the conductivity of the pay zone, this is an indication that the wellbore is approaching, or has even penetrated, the interface of the overlying or underlying earth formation. As an example, the conductivity of an oil-saturated sand may be significantly lower than that of a typical overlying and underlying shale. An indication that the conductivity adjacent the wellbore is increasing can be interpreted to mean that the wellbore is approaching the overlying or the underlying formation layer (shale in this example). The technique of directional drilling using a formation property measurement as a guide to trajectory adjustment is generally referred to as “geosteering.”
In addition to EM measurements, acoustic and radioactive measurements are also used as means for geosteering. Again using the example of an oil producing zone with overlying and underlying shale, natural gamma radioactivity in the pay zone is generally considerably less than the natural gamma ray activity of the shale formations above and below the pay zone. As a result, an increase in the measured natural gamma ray activity from a LWD gamma ray sensor will indicate that the wellbore is deviating from the center of the pay zone and is approaching or even penetrating either the upper or lower shale interface.
If, as in the prior examples, the conductivity and natural radioactivity of the overlying and underlying shale formations are similar to each other, the previously described geosteering techniques indicate only that the wellbore is leaving the pay zone, but do not indicate whether the wellbore is diverting out of the pay zone through the top of the zone or through the bottom of the zone. This presents a problem to the wellbore operator, who must correct the wellbore trajectory to maintain the selected position in the pay zone.
EM induction logging instruments are well suited for geosteering applications because their lateral (radial) depth of investigation into the formations surrounding the wellbore is relatively large, especially when compared to nuclear instruments. The deeper radial investigation enables induction instruments to “see” a significant lateral (or radial) distance from axis of the wellbore. In geosteering applications, this larger depth of investigation would make possible detection of approaching formation layer boundaries at greater lateral distances from the wellbore, which would provide the wellbore operator additional time to make any necessary trajectory corrections. However, conventional propagation-type instruments are capable of resolving axial and lateral (radial) variations in conductivity of the formations surrounding the instrument, but the response of these instruments generally cannot resolve azimuthal variations in the conductivity of the formations surrounding the instrument.
U.S. Pat. Nos. 6,181,138 and 5,892,460 describe the use of TMD antennas to provide directional sensitivity related to bed boundaries. U.S. Pat. No. 5,892,460 proposes using propagation measurements and off-centered antennas from the tool axis for directional measurements. U.S. Pat. Nos. 5,781,436, 5,999,883, and 6,044,325 describe methods for producing estimates of various formation parameters from tri-axial measurements. Disadvantages of these techniques include the coupled effects of dip and formation anisotropy on the resulting measurements.
It is desirable to have measurement techniques that eliminate adverse characteristics of measurements with TMD antennas in geosteering, well placement, directional drilling, or horizontal well drilling applications. It is also desirable to have systems and processes that are insensitive to dip and anisotropy for the estimation of bed boundary parameters.